For much of the past decade, Southeast Europe’s electricity markets have been shaped by a relatively simple commercial logic. Differences in generation costs between the Western Balkans and neighbouring European Union markets created persistent but tradable spreads. Coal-heavy systems in Serbia, Bosnia and Herzegovina, and Montenegro—despite their carbon intensity—often produced electricity at lower marginal cost than gas-driven systems in Italy, Hungary, or Greece. Traders monetised these spreads by exporting power across borders, using interconnectors as conduits for arbitrage. The result was a region where cross-border trading, rather than domestic fundamentals alone, played a central role in price formation and liquidity.
That model has begun to unravel. The introduction of the Carbon Border Adjustment Mechanism (CBAM) in its definitive phase at the start of 2026 has altered the economics of cross-border electricity trade in a way that fundamentally challenges the viability of arbitrage-based strategies. The first quarter of the year provides the clearest evidence yet that the traditional trading architecture of Southeast Europe is no longer intact.
The mechanics of this shift are straightforward in principle but far-reaching in effect. CBAM imposes a carbon cost on electricity imports into the EU, calculated on the basis of default emission factors and linked directly to the EU Emissions Trading System. In Q1 2026, the relevant carbon price averaged €75.36 per tonne of CO₂, translating into effective import costs of approximately €70–86/MWh for electricity originating from coal-dominated systems in the Western Balkans. This additional cost layer does not merely compress margins; in many cases, it eliminates them entirely.
The consequences are visible in the relationship between price spreads and physical flows. In a functioning arbitrage environment, a widening spread between two markets should trigger increased cross-border trade until the spread narrows. In Q1 2026, the opposite occurred. Price differentials between Western Balkan markets and neighbouring EU zones widened to levels rarely observed in recent years—often exceeding €30/MWh, and in some corridors reaching over €40/MWh—yet cross-border flows declined. This disconnect between price signals and trading behaviour is the defining feature of the new market reality.
The Montenegro–Italy corridor offers a particularly illustrative example. Southern Italy recorded some of the highest day-ahead prices in the region, averaging above €130/MWh, while Montenegro’s prices hovered closer to €85/MWh. Under traditional market conditions, a spread of roughly €43/MWh would have supported strong export flows from Montenegro to Italy via the submarine interconnector. Instead, both scheduled and physical flows on this route declined. The reason is not a lack of capacity or demand but the absorption of the price differential by CBAM-related costs. With Montenegro’s default emission factor implying a carbon cost of approximately €73–74/MWh, the apparent arbitrage opportunity is effectively neutralised.
This pattern is not confined to a single corridor. Across the region, similar dynamics are evident. The Serbia–Hungary border, historically one of the most active trading interfaces in Southeast Europe, exhibited a spread of approximately €31/MWh in Q1 2026. Yet this differential failed to generate the expected increase in export flows from Serbia to Hungary. The explanation lies in the same mechanism: CBAM costs, combined with regulatory uncertainty regarding compliance and reporting, have reduced the economic attractiveness of cross-border trades.
The impact of this shift extends beyond spot market activity into the structure of trading strategies themselves. Arbitrage, as traditionally practiced, relies on the ability to capture predictable spreads between markets. When those spreads are subject to policy-driven cost adjustments that can vary with carbon prices, the risk profile changes fundamentally. Traders are no longer dealing with purely market-based variables such as fuel costs, demand patterns, or weather conditions. They must now incorporate regulatory risk, carbon price volatility, and the specifics of CBAM implementation into their decision-making.
This increased complexity has led to more cautious trading behaviour. Evidence from cross-border capacity auctions suggests that market participants reduced their exposure to forward commitments even before CBAM entered into force. Yearly auction prices for interconnection capacity declined by as much as 24–67% on key corridors, reflecting lower expectations of future arbitrage profitability. Daily allocation rates remained high—often above 95%—indicating that capacity continues to be booked, but the value attributed to that capacity has diminished. In effect, interconnectors are still used, but not in the same way or for the same economic purpose.
The transformation is also visible in the performance of regional power exchanges. Total traded volumes across the Western Balkans increased modestly, rising from 2.16 TWh to 2.39 TWh year-on-year, but this aggregate figure masks a significant divergence at the exchange level. Markets with strong domestic generation—particularly hydro-rich systems—experienced substantial growth. Albania’s ALPEX saw volumes roughly double, while Montenegro’s MEPX recorded a 49% increase. By contrast, Serbia’s SEEPEX, which has historically functioned as a hub for transit-based trading, saw volumes decline by 11%. This divergence reflects a broader shift away from arbitrage-driven liquidity towards generation-driven activity.
The decline of transit trading is particularly significant. Prior to 2026, the Western Balkans often served as a corridor for electricity flows between EU markets. For example, power might move from Hungary through Serbia and into Bulgaria, exploiting price differentials along the way. CBAM has disrupted this model by introducing uncertainty regarding the treatment of transit flows. If electricity passing through a non-EU country is subject to carbon costs, even if it originates and is consumed within the EU, the economics of such routes become less attractive. As a result, traders have begun to avoid transit paths involving the Western Balkans, favouring alternative routes that remain entirely within the EU or involve low-emission systems.
This rerouting behaviour has broader implications for the geography of electricity trade. Instead of a network optimised for economic efficiency, flows are increasingly shaped by regulatory considerations. Routes that minimise exposure to CBAM costs become more attractive, even if they are not the shortest or most direct paths. This introduces inefficiencies into the system, as electricity may travel longer distances or through less optimal corridors to avoid carbon charges. Over time, such patterns could alter the utilisation of interconnectors, the development of new infrastructure, and the strategic positioning of different markets within the regional grid.
The erosion of arbitrage also affects the role of interconnectors as financial assets. In liberalised electricity markets, interconnectors are not merely physical links but also instruments for capturing price differentials. Their value is often reflected in the prices paid for capacity rights in auctions. When arbitrage opportunities diminish, so does the willingness of market participants to pay for those rights. The decline in forward auction prices observed at the end of 2025 suggests that investors and traders had already begun to reassess the revenue potential of interconnectors under CBAM conditions. This has implications for future investment decisions, particularly in projects that rely on congestion rents or merchant revenue models.
From a system perspective, the decline in arbitrage-based trading introduces new challenges. Cross-border flows have historically contributed to balancing supply and demand across regions, smoothing price volatility and enhancing security of supply. When these flows are constrained by economic factors rather than physical limitations, the system loses a degree of flexibility. Markets become more reliant on domestic generation, which may not always be the most efficient or cost-effective option. In the longer term, this could lead to higher overall system costs and reduced resilience to shocks.
The interaction between CBAM and EU ETS adds another layer of complexity. Because CBAM costs are directly linked to carbon prices, the economics of arbitrage are now sensitive to developments in the emissions market. In Q1 2026, EU ETS prices declined sharply after an initial increase, reflecting political discussions around potential reforms. This volatility feeds directly into electricity trading decisions, as the cost of importing power from non-EU countries fluctuates with carbon prices. Traders must therefore manage not only power price risk but also carbon price risk, effectively integrating two markets that were previously more loosely connected.
For coal-dependent systems in the Western Balkans, the implications are particularly stark. These markets have traditionally relied on their cost advantage to remain competitive in regional trade. CBAM erodes that advantage by attaching a carbon cost that reflects their higher emission intensity. While this aligns with the broader objective of decarbonisation, it also creates a transitional challenge. Investments in cleaner generation or emissions reduction technologies take time, while the impact of CBAM is immediate. In the interim, these systems may find themselves excluded from cross-border trade, with limited opportunities to monetise their existing generation assets.
At the same time, low-carbon systems—particularly those dominated by hydro—gain a relative advantage. Albania, with a default emission factor effectively equal to zero, can export electricity into the EU without incurring CBAM costs. This creates a strong incentive for traders to source power from such systems, reinforcing their role in regional markets. However, this advantage is contingent on hydrological conditions, which can vary significantly from year to year. The sustainability of this competitive position is therefore uncertain.
Looking ahead, the future of cross-border power trading in Southeast Europe will depend on how market participants adapt to the new environment and how policymakers refine the CBAM framework. Greater clarity on the treatment of transit flows, potential adjustments to default emission factors, and mechanisms for recognising actual generation characteristics could all influence the evolution of trading strategies. At the same time, the development of regional carbon pricing mechanisms aligned with the EU ETS could reduce the asymmetry between EU and non-EU markets, restoring some of the conditions necessary for efficient arbitrage.
What is already evident is that the era of straightforward cross-border arbitrage is coming to an end. The combination of carbon pricing, regulatory uncertainty, and shifting market fundamentals has transformed the landscape in which traders operate. Arbitrage has not disappeared entirely, but it has become more complex, more conditional, and more tightly linked to policy dynamics. For a region that has relied heavily on cross-border trading to drive integration and efficiency, this represents a profound change—one that will continue to shape market behaviour in the years to come.
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